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NOx Emissions from Stationary Gas Turbines - US Environmental ...

NOx Emissions from Stationary Gas Turbines - US Environmental ...

NOx Emissions from Stationary Gas Turbines - US Environmental

Alternative Control Techniques Document— NO x Emissions from Stationary Gas Turbines Emission Standards Division U. S. ENVIRONMENTAL PROTECTION AGENCY Office of Air and Radiation Office of Air Quality Planning and Standards Research Triangle Park, North Carolina 27711 January 1993 EPA-453/R-93-007

  • Page 2 and 3: ALTERNATIVE CONTROL TECHNIQUES DOCU
  • Page 4 and 5: TABLE OF CONTENTS (continued) Secti
  • Page 6 and 7: LIST OF FIGURES Figure Page 2-1 Unc
  • Page 8 and 9: LIST OF FIGURES (continued) Figure
  • Page 10 and 11: LIST OF TABLES Table Page 2-1 UNCON
  • Page 12 and 13: LIST OF TABLES (continued) Table Pa
  • Page 14 and 15: alternative control technique must
  • Page 16 and 17: distillate oil fuels with little or
  • Page 18 and 19: . Uncontrolled NO emission levels r
  • Page 20 and 21: Figure 2-1. Uncontrolled NOx emissi
  • Page 22 and 23: for natural gas and oil fuels, resp
  • Page 24 and 25: localized fuel-rich pockets that pr
  • Page 26 and 27: To date, most SCR systems in the Un
  • Page 28 and 29: Figure 2-3. Capital costs for water
  • Page 30 and 31: combustion were provided by turbine
  • Page 32 and 33: The incremental capital costs range
  • Page 34 and 35: For wet injection, the capital cost
  • Page 36 and 37: Figure 2-7 plots capital costs on a
  • Page 38 and 39: These costs apply to new installati
  • Page 40 and 41: 2-26
  • Page 42 and 43: eason, the costs for gas-fired appl
  • Page 44 and 45: Figure 2-8 indicates that cost effe
  • Page 46 and 47: Figure 2-9 presents SCR cost effect
  • Page 48 and 49: Also, because this cost analysis us
  • Page 50 and 51: For wet injection plus SCR, the com
  • Page 52 and 53:

    the relatively high uncontrolled NO

  • Page 54 and 55:

    Figure 2-11 shows relative achievab

  • Page 56 and 57:

    maintenance requirements are consis

  • Page 58 and 59:

    Figure 3-1 3-44

  • Page 60 and 61:

    presents a cutaway view showing the

  • Page 62 and 63:

    3-5 ; further discussion of combust

  • Page 64 and 65:

    are then diluted with additional co

  • Page 66 and 67:

    , all compressor and turbine stages

  • Page 68 and 69:

    3.2.1 Simple Cycle The simple cycle

  • Page 70 and 71:

    10 Cycle efficiency, defined as a p

  • Page 72 and 73:

    11 . Preheating the combustion air

  • Page 74 and 75:

    3.2.3 Cogeneration Cycle A gas turb

  • Page 76 and 77:

    12 . The steam generated by the exh

  • Page 78 and 79:

    12 , is used to generate electric p

  • Page 80 and 81:

    stand-by/emergency electric power g

  • Page 82 and 83:

    capacity to be purchased by private

  • Page 84 and 85:

    Figure 3-10. Total capacity to be p

  • Page 86 and 87:

    Utility capital cost estimates, as

  • Page 88 and 89:

    , are (1) $500 per KW for repowerin

  • Page 90 and 91:

    economically feasible to install a

  • Page 92 and 93:

    4.0 CHARACTERIZATION OF NO EMISSION

  • Page 94 and 95:

    Figure 4-1. Influence of equivalenc

  • Page 96 and 97:

    4-5

  • Page 98 and 99:

    N 2 in some natural gas, does not c

  • Page 100 and 101:

    takes place. The dependence of ther

  • Page 102 and 103:

    4 for DF-2. Conversely, prompt NO x

  • Page 104 and 105:

    Figure 4-3. Influence of firing tem

  • Page 106 and 107:

    4-15

  • Page 108 and 109:

    Figure 4-4. Influence of relative h

  • Page 110 and 111:

    4-19

  • Page 112 and 113:

    levels. In addition to providing ad

  • Page 114 and 115:

    TABLE 4-1. UNCONTROLLED NO EMISSION

  • Page 116 and 117:

    4-25

  • Page 118 and 119:

    11. Reference 1, p. 3-5. 12. Letter

  • Page 120 and 121:

    5.0 NO CONTROL TECHNIQUES x Nationw

  • Page 122 and 123:

    , effectively sets a limit for new,

  • Page 124 and 125:

    ; and the Northeast States for Coor

  • Page 126 and 127:

    TABLE 5-3. NO EMISSION LIMITS RECOM

  • Page 128 and 129:

    5-37

  • Page 130 and 131:

    Section 5.4. Emissions from duct bu

  • Page 132 and 133:

    summarizes the water quality specif

  • Page 134 and 135:

    5.1.2 Applicability of Wet Controls

  • Page 136 and 137:

    TABLE 5-6. MANUFACTURER'S GUARANTEE

  • Page 138 and 139:

    5-47

  • Page 140 and 141:

    5-49

  • Page 142 and 143:

    Figure 5-1. Percentage of fuel-boun

  • Page 144 and 145:

    5-3. These figures show manufacture

  • Page 146 and 147:

    5-55

  • Page 148 and 149:

    Also presented are the available da

  • Page 150 and 151:

    Figure 5-4. Nitrogen oxide emission

  • Page 152 and 153:

    Figure 5-6. Nitrogen oxide emission

  • Page 154 and 155:

    Figure 5-7. Nitrogen oxide emission

  • Page 156 and 157:

    Figure 5-9. Nitrogen oxide emission

  • Page 158 and 159:

    5-67

  • Page 160 and 161:

    5-69

  • Page 162 and 163:

    5-71

  • Page 164 and 165:

    Figure 5-10. Nitrogen oxide emissio

  • Page 166 and 167:

    and 5-11 for natural gas-fired turb

  • Page 168 and 169:

    . The controlled NO x emissions ran

  • Page 170 and 171:

    . As shown here, NO reductions achi

  • Page 172 and 173:

    5-81

  • Page 174 and 175:

    On a mass basis, the reduction in N

  • Page 176 and 177:

    ; Table TABLE 5-9 shows 5-9. corres

  • Page 178 and 179:

    Figure 5-13. Effect of wet injectio

  • Page 180 and 181:

    Figure 5-14. Effect of water inject

  • Page 182 and 183:

    5-91

  • Page 184 and 185:

    5-93

  • Page 186 and 187:

    No x level, ppmv TABLE 5-10. REPRES

  • Page 188 and 189:

    TABLE 5-11. IMPACTS OF WET CONTROLS

  • Page 190 and 191:

    5-99

  • Page 192 and 193:

    no other changes are made in the co

  • Page 194 and 195:

    Figure 5-15. Nitrogen oxide emissio

  • Page 196 and 197:

    small amount of air and fuel suppli

  • Page 198 and 199:

    . This is a two-stage premixed comb

  • Page 200 and 201:

    Flame is present only in the first

  • Page 202 and 203:

    Figure 5-18 shows a lean premixed c

  • Page 204 and 205:

    The air and fuel are premixed using

  • Page 206 and 207:

    . For operation on natural gas, eac

  • Page 208 and 209:

    . Like the can-annular design, the

  • Page 210 and 211:

    5-119

  • Page 212 and 213:

    delivery into the second combustion

  • Page 214 and 215:

    Figure 5-22. "Stepped" NO and CO em

  • Page 216 and 217:

    5-125

  • Page 218 and 219:

    Figure 5-23. Nitrogen oxide emissio

  • Page 220 and 221:

    TABLE 5-12. MEASURED NO EMISSIONS F

  • Page 222 and 223:

    TABLE 5-13. MEASURED NO EMISSIONS F

  • Page 224 and 225:

    5-133

  • Page 226 and 227:

    combustors are shown in Table 5-14.

  • Page 228 and 229:

    for a 204 MW (274,000 hp) turbine f

  • Page 230 and 231:

    For natural gas-fueled turbines wit

  • Page 232 and 233:

    . At rated load, shown in this figu

  • Page 234 and 235:

    5-143

  • Page 236 and 237:

    Careful selection of equivalence ra

  • Page 238 and 239:

    At an equivalence ratio of 1.8, the

  • Page 240 and 241:

    Increasing the FBN content from 0.1

  • Page 242 and 243:

    natural gas fuel. This combustor de

  • Page 244 and 245:

    Figure 5-27. Cutaway view of a typi

  • Page 246 and 247:

    injection nozzles and effective mix

  • Page 248 and 249:

    Figure 5-28. Possible locations for

  • Page 250 and 251:

    temperature. Below 200EC (400EF), a

  • Page 252 and 253:

    TABLE 5-16. GAS TURBINE INSTALLATIO

  • Page 254 and 255:

    design parameters. With oil fuels,

  • Page 256 and 257:

    As discussed in Section 5.3.1, the

  • Page 258 and 259:

    Test No. TABLE 5-17. EMISSIONS TEST

  • Page 260 and 261:

    were reported, however, in a summar

  • Page 262 and 263:

    from 60 to 96 percent, with most re

  • Page 264 and 265:

    Figure 5-29. Typical duct burner fo

  • Page 266 and 267:

    of duct burner that incorporates de

  • Page 268 and 269:

    For oil-fired burners, the design p

  • Page 270 and 271:

    Figure 5-31. Turbine exhaust gas is

  • Page 272 and 273:

    The reason for this net NO reductio

  • Page 274 and 275:

    5.6 ALTERNATE FUELS Because thermal

  • Page 276 and 277:

    TABLE 5-20. NO EMISSIONS TEST DATA

  • Page 278 and 279:

    Figure 5-32. Influence of load on N

  • Page 280 and 281:

    5-189

  • Page 282 and 283:

    It may be feasible, however, to ini

  • Page 284 and 285:

    Figure 5-34. A rich/lean catalytic

  • Page 286 and 287:

    5-195

  • Page 288 and 289:

    of this study concludes that the te

  • Page 290 and 291:

    20. U. S. Environmental Protection

  • Page 292 and 293:

    44. McKnight, D. (Rolls-Royce Limit

  • Page 294 and 295:

    65. Letter and attachments from Cra

  • Page 296 and 297:

    91. Reference 20, p. 4-23. 92. Refe

  • Page 298 and 299:

    existing gas turbine installation w

  • Page 300 and 301:

    , characterize variations in existi

  • Page 302 and 303:

    TABLE 6-2. FUEL AND WATER FLOW RATE

  • Page 304 and 305:

    TABLE 6-3. FUEL PROPERTIES AND UTIL

  • Page 306 and 307:

    TABLE 6-4. CAPITAL COSTS FOR WET IN

  • Page 308 and 309:

    6-217

  • Page 310 and 311:

    (a) Water injection system. The inj

  • Page 312 and 313:

    The annual costs are summarized in

  • Page 314 and 315:

    for each model plant. Annual costs

  • Page 316 and 317:

    2 (468 ft). Based on these values,

  • Page 318 and 319:

    total cost that must be paid each y

  • Page 320 and 321:

    TABLE 6-6. COST-EFFECTIVENESS SUMMA

  • Page 322 and 323:

    6-231

  • Page 324 and 325:

    Table 6-7 6-233

  • Page 326 and 327:

    presents the uncontrolled and contr

  • Page 328 and 329:

    total capital costs, not costs for

  • Page 330 and 331:

    egression. This equation is shown i

  • Page 332 and 333:

    TABLE 6-10. CAPITAL AND ANNUAL COST

  • Page 334 and 335:

    6-243

  • Page 336 and 337:

    presented in Table 6-8 and are disc

  • Page 338 and 339:

    Manual, the cost to produce steam,

  • Page 340 and 341:

    TABLE 6-11. COST-EFFECTIVENESS SUMM

  • Page 342 and 343:

    model plants using water or steam i

  • Page 344 and 345:

    inlet NO emission level of 25 ppmv

  • Page 346 and 347:

    and 6-14, respectively. These combi

  • Page 348 and 349:

    6-257

  • Page 350 and 351:

    TABLE 6-15. PROJECTED WET INJECTION

  • Page 352 and 353:

    would be estimated by the procedure

  • Page 354 and 355:

    XV. Letter and attachment from Kims

  • Page 356 and 357:

    J., EPA/ISB. May 14, 1992. Response

  • Page 358 and 359:

    7..0 ENVIRONMENTAL AND ENERGY IMPAC

  • Page 360 and 361:

    TABLE 7-1. (continued) Controlled N

  • Page 362 and 363:

    water-to-fuel ratio (WFR), and type

  • Page 364 and 365:

    (N ). The NO removal efficiency of

  • Page 366 and 367:

    Gas turbine model a TABLE 7-2. WATE

  • Page 368 and 369:

    manufacturers. This additional pret

  • Page 370 and 371:

    APPENDIX A Exhaust NO emission leve

  • Page 372 and 373:

    2 turbine manufacturer. Values for

  • Page 374:

    Gas turbine: General Electric LM250

  • Page 377 and 378:

    APPENDIX B. RAW COST DATA AND COST

  • Page 379 and 380:

    calculated and shown in Table B-2 f

  • Page 381 and 382:

    Figure B-1. Total Capital Investmen

  • Page 383 and 384:

    Figure B-3. Catalyst Replacement An

  • Page 385 and 386:

    B-9

  • Page 387 and 388:

    B-11

  • Page 389 and 390:

    B-13

  • Page 391 and 392:

    B-15

  • Page 393 and 394:

    B-17

  • Page 395 and 396:

    TABLE B-3. (Continued) a Total capi

  • Page 397 and 398:

    TABLE B-5. CATALYST REPLACEMENT AND

  • Page 399:

    XII. Sidebotham, G., and R. William

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